The present invention relates to a process for reforming methane and higher hydrocarbons to produce a synthesis gas (syngas) product and/or a hydrogen product. A synthesis gas product is a product comprising primarily CO and H2. Reformed hydrocarbons may be further reacted in one or more shift reactors to form additional H2 in the process stream and separated in a separation unit, such as a pressure swing adsorption unit, to form a H2 product.
Synthesis gas is conventionally used to produce synthesis gas products such as synthetic crude, or further upgraded to form intermediate or end products, for example lubricant basestock, lubricants, greases, middle distillate fuels, diesel, linear alkylbenzenes aviation and jet fuels, gasoline, and other chemicals, i.e. normal- and iso-paraffinic solvents. The synthesis gas may also be used to produce one or more oxygenates, for example, ethers and/or alcohols.
Synthesis gas (including hydrogen) can be produced from methane-containing feedstocks by any number of primary synthesis gas generation reactors. For example, synthesis gas can be produced in a steam methane reformer (SMR), an endothermic reactor where reaction is carried out either in heat exchange reactors, or by other means where substantial heat may be transferred to the reacting fluid, such as in the case of autothermal reforming (ATR), where a portion of the feedstock is combusted inside the reactor to provide heat for steam reforming either subsequently or in the same location as the combustion.
Synthesis gas can also be produced from methane-containing feedstocks by CO2 (“dry”) reforming, catalytic or thermal partial oxidation (CPOx or POx, respectively) and other processes known in the art.
Various feedstocks can be used to produce synthesis gas and industry desires to process multiple feedstocks. Industry desires the ability to change from one feedstock to another during operation without shutting down the reactor. For example, a synthesis gas producer may desire to use natural gas for 6 months, naphtha for 3 months, and then a mixture of natural gas and naphtha for 2 months. Industry desires to process different feedstocks at optimal energy efficiency while avoiding carbon formation in the primary synthesis gas reactor.
In addition to being able to process multiple feedstocks, industry desires to be able to process a feedstock where the composition, particularly the C2+ hydrocarbon concentration in the feedstock, varies over time. For example, synthesis gas may be produced from a refinery offgas where the C2+ hydrocarbon concentration varies from 2 vol. % to 15 vol. % depending on the refinery operation.
If the feedstock contains higher hydrocarbons than methane, that is, hydrocarbons having 2 or more carbon atoms (C2+ hydrocarbons) are used in the reforming process, the risk for catalyst deactivation by carbon deposition in the primary synthesis gas generation reactor is increased. Industry desires to avoid carbon formation in the synthesis gas generation reactor.
In order to reduce the risk of carbon deposition in the primary synthesis gas generation reactor, hydrogen and synthesis gas production processes may employ at least one catalytic reactor prior to the primary synthesis gas generation reactor where the catalytic reactor is operated at conditions less prone to hydrocarbon cracking than the primary synthesis gas generation reactor. These reactors positioned before the primary synthesis gas generation reactors are referred to as pre-reformers. Pre-reformers can be operated adiabatically or convectively heated by indirect heat transfer with combustion products gases from the primary synthesis gas generation reactor.
The activity of the catalyst in the pre-reformer may degrade with use. Industry desires to compensate for the degradation of the pre-reforming catalyst through operational changes to avoid carbon formation in the primary synthesis gas generation reactor while maintaining optimal energy efficiency of the overall process.
In hydrogen and synthesis gas production processes employing pre-reformers and steam methane reformers, the hydrocarbon feedstock may be mixed with hydrogen for a resultant stream having 1 to 5% hydrogen by volume, and subsequently subjected to a hydrodesulphurization (HDS) pretreatment to remove sulphur. The hydrocarbon feedstock may also be treated to remove olefins in a hydrogenation reactor. In case H2 is present in the feedstock, additional H2 might not be added.
For steam reforming of heavy naphthas, hydrogen concentrations as high as about 50 volume % H2 are known where the mixture is subsequently pretreated in a hydrodesulphurization unit and/or a hydrogenation reactor. Even higher hydrogen concentrations are possible depending on the feedstock provided.
The feedstock, after pretreating, is combined with superheated steam to form “mixed feed” having a prescribed steam-to-carbon molar ratio. The steam-to-carbon molar ratio, S/C, is the ratio of the molar flow rate of steam in the mixed feed to the molar flow rate of hydrocarbon-based carbon in the mixed feed. The “steam-to-carbon molar ratio” is a conventional term used in the art.
The steam-to-carbon molar ratio for steam methane reforming of natural gas typically ranges from 2 to 5, but can be as low as 1.5. The steam-to-carbon molar ratio is generally higher for steam methane reforming of feedstock containing a greater amount of higher hydrocarbons, for example, propane, butane, propane/butane mixtures, and naphtha.
Higher steam flow rates are used to suppress carbon formation and enhance the steam reforming reaction. However, higher steam-to-carbon molar ratios disadvantageously decrease the energy efficiency of the reforming process. Industry desires to improve the energy efficiency of steam-hydrocarbon reforming systems.